Document
 
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
  
(Mark One)
ý
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the Quarterly Period Ended March 31, 2019
OR
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period _______________ to _______________
Commission File Number: 001-37362
Black Stone Minerals, L.P.
(Exact name of registrant as specified in its charter)
 
Delaware
 
47-1846692
(State or other jurisdiction of
incorporation or organization)
 
(I.R.S. Employer
Identification No.)
 
 
 
1001 Fannin Street, Suite 2020
Houston, Texas
 
77002
(Address of principal executive offices)
 
(Zip code)
(713) 445-3200
(Registrant’s telephone number, including area code)
 
Securities registered pursuant to Section 12(b) of the Act:
Title of each class
 
Trading Symbol(s)
 
Name of each exchange on which registered
Common Units Representing Limited Partner Interests
 
BSM
 
New York Stock Exchange
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports) and (2) has been subject to such filing requirements for the past 90 days. Yes ý  No ☐  
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ý No ☐ 
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and "emerging growth company" in Rule 12b-2 of the Exchange Act. 
 
Large accelerated filer
ý
 
 
Accelerated filer
 
 
Non-accelerated filer
(Do not check if a smaller reporting company)
 
Smaller reporting company
 
 
 
 
 
 
Emerging growth company
 
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes ☐  No ý
As of April 30, 2019, there were 109,382,957 common units, 96,328,836 subordinated units, and 14,711,219 Series B cumulative convertible preferred units of the registrant outstanding.
 



TABLE OF CONTENTS
 
 
 
Page
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 





ii


PART I – FINANCIAL INFORMATION


Item 1. Financial Statements 


BLACK STONE MINERALS, L.P. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
(In thousands)
 
 
March 31, 2019
 
December 31, 2018
ASSETS
 
 

 
 

CURRENT ASSETS
 
 

 
 

Cash and cash equivalents
 
$
4,247

 
$
5,414

Accounts receivable
 
103,327

 
113,148

Commodity derivative assets
 
4,012

 
37,970

Prepaid expenses and other current assets
 
1,543

 
1,001

TOTAL CURRENT ASSETS
 
113,129

 
157,533

PROPERTY AND EQUIPMENT
 
 

 
 

Oil and natural gas properties, at cost, using the successful efforts method of accounting, includes unproved properties of $1,084,737 and $1,063,883 at March 31, 2019 and December 31, 2018, respectively
 
3,477,494

 
3,441,188

Accumulated depreciation, depletion, amortization, and impairment
 
(1,893,461
)
 
(1,865,692
)
Oil and natural gas properties, net
 
1,584,033

 
1,575,496

Other property and equipment, net of accumulated depreciation of $11,115 and $11,048 at March 31, 2019 and December 31, 2018, respectively
 
2,353

 
385

NET PROPERTY AND EQUIPMENT
 
1,586,386

 
1,575,881

DEFERRED CHARGES AND OTHER LONG-TERM ASSETS
 
12,372

 
16,710

TOTAL ASSETS
 
$
1,711,887

 
$
1,750,124

LIABILITIES, MEZZANINE EQUITY, AND EQUITY
 
 
 
 

CURRENT LIABILITIES
 
 
 
 

Accounts payable
 
$
6,639

 
$
4,149

Accrued liabilities
 
38,977

 
60,089

Commodity derivative liabilities
 
1,967

 

Other current liabilities
 
926

 
528

TOTAL CURRENT LIABILITIES
 
48,509

 
64,766

LONG–TERM LIABILITIES
 
 
 
 

Credit facility
 
435,000

 
410,000

Accrued incentive compensation
 
1,028

 
1,813

Commodity derivative liabilities
 
23

 

Asset retirement obligations
 
15,146

 
14,948

Other long-term liabilities
 
78,292

 
55,973

TOTAL LIABILITIES
 
577,998

 
547,500

COMMITMENTS AND CONTINGENCIES (Note 8)
 


 


MEZZANINE EQUITY
 
 

 
 

Partners' equity – Series B cumulative convertible preferred units, 14,711 and 14,711 units outstanding at March 31, 2019 and December 31, 2018, respectively
 
298,361

 
298,361

EQUITY
 
 
 
 

Partners' equity – general partner interest
 

 

Partners' equity – common units, 109,377 and 108,363 units outstanding at March 31, 2019 and December 31, 2018, respectively
 
679,868

 
714,823

Partners' equity – subordinated units, 96,329 and 96,329 units outstanding at March 31, 2019 and December 31, 2018, respectively
 
155,660

 
189,440

TOTAL EQUITY
 
835,528

 
904,263

TOTAL LIABILITIES, MEZZANINE EQUITY, AND EQUITY
 
$
1,711,887

 
$
1,750,124

The accompanying notes are an integral part of these unaudited consolidated financial statements.

1



BLACK STONE MINERALS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)
(In thousands, except per unit amounts)

 
 
Three Months Ended March 31,
 
 
2019
 
2018
REVENUE

 


 

Oil and condensate sales

$
57,704


$
72,983

Natural gas and natural gas liquids sales

61,640


53,245

Lease bonus and other income

5,645


4,599

Revenue from contracts with customers

124,989


130,827

Gain (loss) on commodity derivative instruments

(41,183
)

(16,333
)
TOTAL REVENUE

83,806


114,494

OPERATING (INCOME) EXPENSE

 


 

Lease operating expense

5,292


4,248

Production costs and ad valorem taxes

14,592


14,925

Exploration expense

4


3

Depreciation, depletion, and amortization

27,833


28,570

General and administrative

21,214


18,521

Accretion of asset retirement obligations

277


269

(Gain) loss on sale of assets, net



(2
)
TOTAL OPERATING EXPENSE

69,212


66,534

INCOME (LOSS) FROM OPERATIONS

14,594


47,960

OTHER INCOME (EXPENSE)

 

 

Interest and investment income

46


33

Interest expense

(5,525
)

(4,521
)
Other income (expense)

(98
)

(1,515
)
TOTAL OTHER EXPENSE

(5,577
)

(6,003
)
NET INCOME (LOSS)

9,017


41,957

Net (income) loss attributable to noncontrolling interests



(27
)
Distributions on Series A redeemable preferred units



(25
)
Distributions on Series B cumulative convertible preferred units

(5,250
)

(5,250
)
NET INCOME (LOSS) ATTRIBUTABLE TO THE GENERAL PARTNER AND COMMON AND SUBORDINATED UNITS

$
3,767


$
36,655

ALLOCATION OF NET INCOME (LOSS):

 


 

General partner interest

$


$

Common units

1,905


24,329

Subordinated units

1,862


12,326

 

$
3,767


$
36,655

NET INCOME (LOSS) ATTRIBUTABLE TO LIMITED PARTNERS PER COMMON AND SUBORDINATED UNIT:

 


 

Per common unit (basic)

$
0.02


$
0.23

Weighted average common units outstanding (basic)

109,420


103,774

Per subordinated unit (basic)

$
0.02


$
0.13

Weighted average subordinated units outstanding (basic)

96,329


95,395

Per common unit (diluted)

$
0.02


$
0.23

Weighted average common units outstanding (diluted)

110,035


103,838

Per subordinated unit (diluted)

$
0.02


$
0.13

Weighted average subordinated units outstanding (diluted)

96,329


95,395

 The accompanying notes are an integral part of these unaudited consolidated financial statements.

2



BLACK STONE MINERALS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF EQUITY
(Unaudited)
(In thousands)

 
 
Three-Month Period Ended March 31, 2019
 
 
Common units
 
Subordinated units
 
Partners' equity — common units
 
Partners' equity — subordinated units
 
Total equity
BALANCE AT DECEMBER 31, 2018
 
108,363

 
96,329

 
$
714,823

 
$
189,440

 
$
904,263

Repurchases of common and subordinated units
 
(588
)
 

 
(10,110
)
 

 
(10,110
)
Issuance of common units, net of offering costs
 

 

 
(43
)
 

 
(43
)
Issuance of common units for property acquisitions
 
57

 

 
943

 

 
943

Restricted units granted, net of forfeitures
 
1,545

 

 

 

 

Equity–based compensation
 

 

 
13,669

 

 
13,669

Distributions
 

 

 
(40,275
)
 
(35,642
)
 
(75,917
)
Charges to partners' equity for accrued distribution equivalent rights
 

 

 
(1,044
)
 

 
(1,044
)
Distributions on Series B cumulative convertible preferred units
 

 

 
(5,250
)
 

 
(5,250
)
Net income (loss)
 

 

 
7,155

 
1,862

 
9,017

BALANCE AT MARCH 31, 2019
 
109,377

 
96,329

 
$
679,868

 
$
155,660

 
$
835,528

 
 
 
Three-Month Period Ended March 31, 2018
 
 
Common units
 
Subordinated units
 
Partners' equity — common units
 
Partners' equity — subordinated units
 
Noncontrolling interests
 
Total equity
BALANCE AT DECEMBER 31, 2017
 
103,456

 
95,388

 
$
603,116

 
$
164,138

 
$
867

 
$
768,121

Conversion of Series A redeemable preferred units
 
736

 
964

 
10,498

 
13,750

 

 
24,248

Repurchases of common and subordinated units
 
(451
)
 
(23
)
 
(8,099
)
 
(342
)
 

 
(8,441
)
Issuance of common units, net of offering costs
 
8

 

 
138

 

 

 
138

Restricted units granted, net of forfeitures
 
1,177

 

 

 

 

 

Equity–based compensation1
 

 

 
18,075

 
219

 

 
18,294

Distributions
 

 

 
(32,581
)
 
(19,912
)
 
(52
)
 
(52,545
)
Charges to partners' equity for accrued distribution equivalent rights
 

 

 
(661
)
 

 

 
(661
)
Distributions on Series A redeemable preferred units
 

 

 
(13
)
 
(12
)
 

 
(25
)
Distributions on Series B cumulative convertible preferred units
 

 

 
(5,250
)
 

 

 
(5,250
)
Net income (loss)
 

 

 
29,592

 
12,338

 
27

 
41,957

BALANCE AT MARCH 31, 2018
 
104,926

 
96,329

 
$
614,815

 
$
170,179

 
$
842

 
$
785,836

1  
The change in Partners' equity for equity-based compensation during the three-month period ended March 31, 2018 was incorrectly allocated between Partners' equity - common units and Partners' equity - subordinated units in the Partnership's prior reports. The Partnership concluded that this error was not material to any of the prior reporting periods. As such, the revision for this correction has been made to the prior periods presented.
The accompanying notes are an integral part of these unaudited consolidated financial statements.

3



BLACK STONE MINERALS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
(In thousands)

 
 
Three Months Ended March 31,
 
 
2019
 
2018
CASH FLOWS FROM OPERATING ACTIVITIES
 
 

 
 

Net income (loss)
 
$
9,017

 
$
41,957

Adjustments to reconcile net income (loss) to net cash provided by operating activities:
 
 
 
 

Depreciation, depletion, and amortization
 
27,833

 
28,570

Accretion of asset retirement obligations
 
277

 
269

Amortization of deferred charges
 
257

 
205

(Gain) loss on commodity derivative instruments
 
41,183

 
16,333

Net cash (paid) received on settlement of commodity derivative instruments
 
1,743

 
(4,375
)
Equity-based compensation
 
9,223

 
6,226

Exploratory dry hole expense
 
4

 

(Gain) loss on sale of assets, net
 

 
(2
)
Changes in operating assets and liabilities:
 
 
 
 
Accounts receivable
 
9,740

 
(11,851
)
Prepaid expenses and other current assets
 
(541
)
 
(260
)
Accounts payable, accrued liabilities, and other
 
(8,522
)
 
(565
)
Settlement of asset retirement obligations
 
(40
)
 
(33
)
NET CASH PROVIDED BY OPERATING ACTIVITIES
 
90,174

 
76,474

CASH FLOWS FROM INVESTING ACTIVITIES
 
 

 
 

Acquisitions of oil and natural gas properties
 
(19,946
)
 
(32,154
)
Additions to oil and natural gas properties
 
(31,633
)
 
(46,250
)
Additions to oil and natural gas properties leasehold costs
 
(234
)
 
(524
)
Purchases of other property and equipment
 
(2,036
)
 
(5
)
Proceeds from the sale of oil and natural gas properties
 
2

 
752

Proceeds from farmouts of oil and natural gas properties
 
29,468

 
18,015

NET CASH USED IN INVESTING ACTIVITIES
 
(24,379
)
 
(60,166
)
CASH FLOWS FROM FINANCING ACTIVITIES
 
 

 
 

Proceeds from issuance of common units, net of offering costs
 
(43
)
 
138

Distributions to common and subordinated unitholders
 
(75,917
)
 
(52,493
)
Distributions to Series A redeemable preferred unitholders
 

 
(690
)
Distributions to Series B cumulative convertible preferred unitholders
 
(5,250
)
 

Distributions to noncontrolling interests
 

 
(52
)
Redemptions of Series A redeemable preferred units
 

 
(2,115
)
Repurchases of common and subordinated units
 
(10,752
)
 
(8,441
)
Borrowings under credit facility
 
98,000

 
105,000

Repayments under credit facility
 
(73,000
)
 
(57,000
)
NET CASH USED IN FINANCING ACTIVITIES
 
(66,962
)
 
(15,653
)
NET CHANGE IN CASH AND CASH EQUIVALENTS
 
(1,167
)
 
655

CASH AND CASH EQUIVALENTS – beginning of the period
 
5,414

 
5,642

CASH AND CASH EQUIVALENTS – end of the period
 
$
4,247

 
$
6,297

SUPPLEMENTAL DISCLOSURE
 
 
 
 
Interest paid
 
$
5,197

 
$
4,326

 The accompanying notes are an integral part of these unaudited consolidated financial statements.

4


BLACK STONE MINERALS, L.P. AND SUBSIDIARIES
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS



NOTE 1 — BUSINESS AND BASIS OF PRESENTATION
Description of the Business
Black Stone Minerals, L.P. (“BSM” or the “Partnership”) is a publicly traded Delaware limited partnership that owns oil and natural gas mineral interests, which make up the vast majority of the asset base. The Partnership's assets also include nonparticipating royalty interests and overriding royalty interests. These interests, which are substantially non-cost-bearing, are collectively referred to as “mineral and royalty interests.” The Partnership’s mineral and royalty interests are located in 41 states in the continental United States, including all of the major onshore producing basins. The Partnership also owns non-operated working interests in certain oil and natural gas properties. The Partnership's common units trade on the New York Stock Exchange under the symbol "BSM."
Basis of Presentation
The accompanying unaudited interim consolidated financial statements of the Partnership have been prepared in accordance with generally accepted accounting principles ("GAAP") in the United States and pursuant to the rules and regulations of the U.S. Securities and Exchange Commission (“SEC”). These unaudited interim consolidated financial statements have been prepared in accordance with the instructions to Form 10-Q and, therefore, do not include all disclosures required for financial statements prepared in conformity with GAAP. Accordingly, the accompanying unaudited interim consolidated financial statements and related notes should be read in conjunction with the Partnership’s consolidated financial statements included in the Partnership’s 2018 Annual Report on Form 10-K.
The consolidated financial statements include the consolidated results of the Partnership. The results of operations for the three months ended March 31, 2019 are not necessarily indicative of the results to be expected for the full year.
In the opinion of management, all adjustments, which are of a normal and recurring nature, necessary for the fair presentation of the financial results for all periods presented have been reflected. All intercompany balances and transactions have been eliminated.
The Partnership evaluates the significant terms of its investments to determine the method of accounting to be applied to each respective investment. Investments in which the Partnership has less than a 20% ownership interest and does not have control or exercise significant influence are accounted for using fair value or cost minus impairment if fair value is not readily determinable. Investments in which the Partnership exercises control are consolidated, and the noncontrolling interests of such investments, which are not attributable directly or indirectly to the Partnership, are presented as a separate component of net income and equity in the accompanying consolidated financial statements.
The unaudited interim consolidated financial statements include undivided interests in oil and natural gas property rights. The Partnership accounts for its share of oil and natural gas property rights by reporting its proportionate share of assets, liabilities, revenues, costs, and cash flows within the relevant lines on the accompanying unaudited interim consolidated balance sheets, statements of operations, and statements of cash flows.
Segment Reporting
The Partnership operates in a single operating and reportable segment. Operating segments are defined as components of an enterprise for which separate financial information is evaluated regularly by the chief operating decision maker in deciding how to allocate resources and assess performance. The Partnership’s chief executive officer has been determined to be the chief operating decision maker and allocates resources and assesses performance based upon financial information at the consolidated level.

5


BLACK STONE MINERALS, L.P. AND SUBSIDIARIES
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS


NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Significant Accounting Policies
Significant accounting policies are disclosed in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2018. There have been no changes in such policies or the application of such policies during the three months ended March 31, 2019, with the exception of ASC 842, as defined below.
Accounts Receivable

The following table presents information about the Partnership's accounts receivable:
 
 
March 31, 2019
 
December 31, 2018
 
 
 
 
 
 
 
(in thousands)
Accounts receivable:
 
 
 
 
Revenues from contracts with customers
 
$
97,816

 
$
107,804

Other
 
5,511

 
5,344

Total accounts receivable
 
$
103,327

 
$
113,148

Recent Accounting Pronouncements

In February 2016, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") 2016-02, Leases (Topic 842), that supersedes Accounting Standards Codification ("ASC") 840, Leases by requiring lessees to recognize lease assets and lease liabilities classified as operating leases on the balance sheet. See Note 3 - Impact of ASC 842 Adoption for further details related to the Partnership's adoption of this standard.
In August 2018, the FASB issued ASU 2018-13, Fair Value Measurement (Topic 820), which will remove, modify, and add certain required disclosures on fair value measurements. As amended, Topic 820 will no longer require the disclosure of the amount of and reasons for transfers between Level 1 and Level 2 of the fair value hierarchy, the policy of timing of transfers between levels, and the valuation processes for Level 3 fair value measurements. In addition, certain modifications to current disclosure requirements will be made, including clarifying that the measurement uncertainty disclosure is to communicate information about the uncertainty in measurement as of the reporting date. Certain disclosure requirements will also be added, including the range and weighted average of significant unobservable inputs used to develop Level 3 fair value measurements. For certain unobservable inputs, an entity may disclose other quantitative information in place of the weighted average if the entity determines that other quantitative information would be a more reasonable and rational method to reflect the distribution of unobservable inputs used to develop Level 3 fair value measurements. The new standard will be effective for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years, and early adoption is permitted. The Partnership does not plan to early adopt and is evaluating the impact that the new accounting guidance will have on its consolidated financial statements and related disclosures.
NOTE 3 — IMPACT OF ASC 842 ADOPTION
Leases
On January 1, 2019, the Partnership adopted ASU 2016-02, Leases (Topic 842) using the modified retrospective method. This ASU requires the recognition of lease assets and lease liabilities by lessees for those leases classified as operating leases under the previous guidance. The Partnership used January 1, 2019, the beginning of the period of adoption, as its date of initial application. The Partnership elected the package of practical expedients upon transition which will retain the lease classification for leases and any unamortized initial direct costs that existed prior to the adoption of the standard.
The adoption of the standard resulted in the recognition of operating lease right-of-use (“ROU”) assets and operating lease liabilities on the consolidated balance sheet as of January 1, 2019. ROU assets and operating lease liabilities were less than 1% of the Partnership's total assets as of March 31, 2019 and were not considered material to the Partnership. There was no related impact on the consolidated statement of operations. The standard had no impact on the Partnership’s debt covenant compliance under existing agreements.

6


BLACK STONE MINERALS, L.P. AND SUBSIDIARIES
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS


The Partnership determines if an arrangement is a lease at inception by considering whether (1) explicitly or implicitly identified assets have been deployed in the agreement and (2) the Partnership obtains substantially all of the economic benefits from the use of that underlying asset and directs how and for what purpose the asset is used during the term of the agreement. Operating leases are included in Deferred charges and other long-term assets, Other current liabilities, and Other long-term liabilities in the consolidated balance sheets. As of March 31, 2019, none of the Partnership’s leases were classified as financing leases.
ROU assets represent the Partnership’s right to use an underlying asset for the lease term and operating lease liabilities represent the Partnership’s obligation to make lease payments arising from the lease. ROU assets are recognized at commencement date and consist of the present value of remaining lease payments over the lease term, initial direct costs, prepaid lease payments less any lease incentives. Operating lease liabilities are recognized at commencement date based on the present value of remaining lease payments over the lease term. The Partnership uses the implicit rate, when readily determinable, or its incremental borrowing rate based on the information available at commencement date to determine the present value of lease payments.
The lease terms may include periods covered by options to extend the lease when it is reasonably certain that the Partnership will exercise that option and periods covered by options to terminate the lease when it is not reasonably certain that the Partnership will exercise that option. Lease expense for lease payments is recognized on a straight-line basis over the lease term. The Partnership made an accounting policy election to not recognize leases with terms of less than twelve months on the consolidated balance sheets and recognize those lease payments in the consolidated statements of operations on a straight-line basis over the lease term. In the event that the Partnership’s assumptions and expectations change, it may have to revise its ROU assets and operating lease liabilities.
NOTE 4 — OIL AND NATURAL GAS PROPERTIES ACQUISITIONS    
Acquisitions of proved oil and natural gas properties and working interests are considered business combinations and are recorded at their estimated fair value as of the acquisition date. Acquisitions of unproved oil and natural gas properties are considered asset acquisitions and are recorded at cost.
2019 Acquisitions
During the three months ended March 31, 2019, the Partnership closed on multiple acquisitions of mineral and royalty interests for total consideration of $20.9 million.
Acquisitions that included proved oil and natural gas properties were considered business combinations and were primarily located in the Permian Basin. These acquisitions were funded with borrowings under the Credit Facility (as defined in Note 7 - Credit Facility) and funds from operating activities. Acquisition related costs of less than $0.1 million were expensed and included in the General and administrative expense line item of the consolidated statement of operations for the three months ended March 31, 2019. The following table summarizes these acquisitions which were considered business combinations:
 
Assets Acquired
 
Consideration Paid
 
Proved
 
Unproved
 
Net Working Capital
 
Total Fair Value
 
Cash
 
 
 
 
 
 
 
 
 
 
 
(in thousands)
February
$
173

 
$
8,437

 
$
1

 
$
8,611

 
$
8,611

March
24

 

 

 
24

 
24

Total fair value
$
197


$
8,437


$
1


$
8,635


$
8,635


7


BLACK STONE MINERALS, L.P. AND SUBSIDIARIES
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS


In addition, during the three months ended March 31, 2019, the Partnership acquired mineral and royalty interests in unproved oil and natural gas properties from various sellers for an aggregate of $12.3 million. These acquisitions were considered asset acquisitions and were primarily located in East Texas. The cash portion of the consideration paid for these acquisitions of $11.4 million was funded with borrowings under the Credit Facility and funds from operating activities, and $0.9 million was funded through the issuance of common units of the Partnership based on the fair values of the common units issued on the acquisition dates.
2018 Acquisitions

During the year ended December 31, 2018, the Partnership closed on multiple acquisitions of mineral and royalty interests for total consideration of $149.9 million.
Acquisitions that included proved oil and natural gas properties were considered business combinations and were primarily located in the Permian Basin. The cash portion of the consideration paid for these acquisitions was funded with borrowings under the Credit Facility and funds from operating activities. Acquisition related costs of $0.2 million were expensed and included in the General and administrative expense line item of the consolidated statement of operations for the year ended December 31, 2018. The following table summarizes these acquisitions which were considered business combinations:
 
Assets Acquired
 
Consideration Paid
 
Proved
 
Unproved
 
Net Working Capital
 
Total Fair Value
 
Cash
 
Fair Value of Common Units Issued
 
 
 
 
 
(in thousands)
 
 
 
 
 
 
March
$
984

 
$
21,452

 
$
133

 
$
22,569

 
$
22,569

 
$

June
883

 
13,688

 
8

 
14,579

 
14,579

 

July
4,349

 
7,944

 
215

 
12,508

 
3,764

 
8,744

August
5,000

 
34,673

 
74

 
39,747

 
26,461

 
13,286

September
1,176

 

 

 
1,176

 
1,176

 

November
1,166

 

 

 
1,166

 
1,166

 

Total fair value
$
13,558

 
$
77,757

 
$
430

 
$
91,745

 
$
69,715

 
$
22,030


In addition, during 2018, the Partnership acquired mineral and royalty interests in unproved oil and natural gas properties from various sellers for an aggregate of $58.2 million. These acquisitions were considered asset acquisitions and were primarily located in East Texas and the Permian Basin. The cash portion of the consideration paid for these acquisitions of $57.6 million was funded with borrowings under the Credit Facility and funds from operating activities, and $0.6 million was funded through the issuance of common units of the Partnership based on the fair values of the common units issued on the acquisition dates.

During 2018, the Partnership acquired the remaining noncontrolling interest in certain subsidiaries for $1.7 million in cash and merged the subsidiaries into its existing structure.
Farmout Agreements
Canaan Farmout
On February 21, 2017, the Partnership announced that it had entered into a farmout agreement with Canaan Resource Partners ("Canaan") which covers certain Haynesville and Bossier shale acreage in San Augustine County, Texas operated by XTO Energy Inc., a subsidiary of Exxon Mobil Corporation. The Partnership has an approximate 50% working interest in the acreage and is the largest mineral owner. A total of 20 wells were drilled over an initial phase, beginning with wells spud after January 1, 2017. Canaan has elected to participate in an additional phase that began in September 2018 and will continue for the lesser of 2 years or until 20 wells have been drilled. After the completion of the second phase, Canaan will have the option to elect to participate in a similar third phase. During the first three phases of the agreement, Canaan commits on a phase-by-phase basis and funds 80% of the Partnership's drilling and completion costs and is assigned 80% of the Partnership's working interests in such wells (40% working interest on an 8/8ths basis) as the wells are drilled. After the third phase, Canaan can earn 40% of the Partnership’s working interest (20% working interest on an 8/8ths basis) in additional wells drilled in the area by continuing to fund 40% of the Partnership's costs for those wells on a well-by-well basis. The Partnership will receive an

8


BLACK STONE MINERALS, L.P. AND SUBSIDIARIES
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS


overriding royalty interest (“ORRI”) before payout and an increased ORRI after payout on all wells drilled under the agreement. From the inception of the agreement through March 31, 2019, the Partnership has received $86.4 million from Canaan under the agreement. As of March 31, 2019, the Partnership had assigned to Canaan working interests in certain wells drilled and completed, and as such, $8.9 million of the farmout reimbursements received from Canaan are included in the Other long-term liabilities line item of the consolidated balance sheet.
Pivotal Farmout
On November 21, 2017, the Partnership entered into a farmout agreement with Pivotal Petroleum Partners (“Pivotal”), a portfolio company of Tailwater Capital, LLC. The farmout agreement covers substantially all of the Partnership's remaining working interests under active development in the Shelby Trough area of East Texas, targeting the Haynesville and Bossier shale acreage (after giving effect to the Canaan Farmout), until November 2025. In wells operated by XTO Energy Inc. in San Augustine County, Texas, Pivotal will earn the Partnership's remaining working interest not covered by the Canaan Farmout (10% working interest on an 8/8th basis), as well as 100% of the Partnership's working interests (ranging from approximately 12.5% to 25% on an 8/8ths basis) in wells operated by its other major operator in San Augustine and Angelina counties, Texas. Initially, Pivotal is obligated to fund the development of up to 80 wells across several development areas and then has options to continue funding the Partnership's working interest across those areas for the duration of the farmout agreement. Pivotal will fund designated groups of wells. Once Pivotal achieves a specified payout for a designated well group, the Partnership will obtain a majority of the original working interest in such well group. From the inception of the agreement through March 31, 2019, the Partnership received $86.8 million from Pivotal under the agreement. As of March 31, 2019, the Partnership had assigned to Pivotal working interests in certain wells drilled and completed, and as such, $63.1 million of the farmout reimbursements received from Pivotal are included in the Other long-term liabilities line item of the consolidated balance sheet.
As of December 31, 2018, $11.6 million and $41.2 million were included in the Other long-term liabilities line item of the consolidated balance sheet related to the farmout agreements with Canaan and Pivotal, respectively.
NOTE 5 — COMMODITY DERIVATIVE FINANCIAL INSTRUMENTS
The Partnership’s ongoing operations expose it to changes in the market price for oil and natural gas. To mitigate the inherent commodity price risk associated with its operations, the Partnership uses oil and natural gas commodity derivative financial instruments. From time to time, such instruments may include variable-to-fixed-price swaps, costless collars, fixed-price contracts and other contractual arrangements. The Partnership enters into oil and natural gas derivative contracts that contain netting arrangements with each counterparty. The Partnership does not enter into derivative instruments for speculative purposes.
As of March 31, 2019, the Partnership’s open derivative contracts consisted of fixed-price swap contracts and costless collar contracts. A fixed-price swap contract between the Partnership and the counterparty specifies a fixed commodity price and a future settlement date. A costless collar contract between the Partnership and the counterparty specifies a floor and a ceiling commodity price and a future settlement date. The Partnership has not designated any of its contracts as fair value or cash flow hedges. Accordingly, the changes in the fair value of the contracts are included in the consolidated statement of operations in the period of the change. All derivative gains and losses from the Partnership’s derivative contracts have been recognized in revenue in the Partnership's accompanying consolidated statements of operations. Derivative instruments that have not yet been settled in cash are reflected as either derivative assets or liabilities in the Partnership’s accompanying consolidated balance sheets as of March 31, 2019 and December 31, 2018. See Note 6 – Fair Value Measurements for further discussion.    
The Partnership's derivative contracts expose it to credit risk in the event of nonperformance by counterparties that may adversely impact the fair value of the Partnership's commodity derivative assets. While the Partnership does not require its derivative contract counterparties to post collateral, the Partnership does evaluate the credit standing of such counterparties as deemed appropriate. This evaluation includes reviewing a counterparty’s credit rating and latest financial information. As of March 31, 2019, the Partnership had nine counterparties, all of which are rated Baa1 or better by Moody’s and are lenders under the Credit Facility.

9


BLACK STONE MINERALS, L.P. AND SUBSIDIARIES
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS


The tables below summarize the fair values and classifications of the Partnership’s derivative instruments, as well as the gross recognized derivative assets, liabilities, and amounts offset in the consolidated balance sheets as of each date:
 
 
 
 
March 31, 2019
Classification
 
Balance Sheet Location
 
Gross
Fair Value
 
Effect of Counterparty Netting
 
Net Carrying Value on Balance Sheet
 
 
 
 
 
 
 
 
 
 
 
 
 
(in thousands)
Assets:
 
 
 
 

 
 

 
 

Current asset
 
Commodity derivative assets
 
$
11,221

 
$
(7,209
)
 
$
4,012

Long-term asset
 
Deferred charges and other long-term assets
 
5,438

 
(2,348
)
 
3,090

 Total assets
 
 
 
$
16,659

 
$
(9,557
)
 
$
7,102

Liabilities:
 
 
 
 

 
 

 
 

Current liability
 
Commodity derivative liabilities
 
$
9,176

 
$
(7,209
)
 
$
1,967

Long-term liability
 
Commodity derivative liabilities
 
2,371

 
(2,348
)
 
23

Total liabilities
 
 
 
$
11,547

 
$
(9,557
)
 
$
1,990

 
 
 
 
December 31, 2018
Classification
 
Balance Sheet Location
 
Gross
Fair Value
 
Effect of Counterparty Netting
 
Net Carrying Value on Balance Sheet
 
 
 
 
 
 
 
 
 
 
 
 
 
(in thousands)
Assets:
 
 
 
 

 
 

 
 

Current asset
 
Commodity derivative assets
 
$
38,746

 
$
(776
)
 
$
37,970

Long-term asset
 
Deferred charges and other long-term assets
 
11,518

 
(1,450
)
 
10,068

 Total assets
 
 
 
$
50,264

 
$
(2,226
)
 
$
48,038

Liabilities:
 
 
 
 

 
 

 
 

Current liability
 
Commodity derivative liabilities
 
$
776

 
$
(776
)
 
$

Long-term liability
 
Commodity derivative liabilities
 
1,450

 
(1,450
)
 

Total liabilities
 
 
 
$
2,226

 
$
(2,226
)
 
$

Changes in the fair values of the Partnership’s derivative instruments (both assets and liabilities) are presented on a net basis in the accompanying consolidated statements of operations and consolidated statements of cash flows and consist of the following for the periods presented:
 
 
Three Months Ended March 31,
Derivatives not designated as hedging instruments
 
2019
 
2018
 
 
(in thousands)
Beginning fair value of commodity derivative instruments
 
$
48,038

 
$
(5,028
)
Gain (loss) on oil derivative instruments
 
(39,261
)
 
(14,476
)
Gain (loss) on natural gas derivative instruments
 
(1,922
)
 
(1,857
)
Net cash paid (received) on settlements of oil derivative instruments
 
(4,555
)
 
5,148

Net cash paid (received) on settlements of natural gas derivative instruments
 
2,812

 
(773
)
Net change in fair value of commodity derivative instruments
 
(42,926
)
 
(11,958
)
Ending fair value of commodity derivative instruments
 
$
5,112

 
$
(16,986
)

10


BLACK STONE MINERALS, L.P. AND SUBSIDIARIES
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS


The Partnership had the following open derivative contracts for oil as of March 31, 2019:
 
 

 
Weighted Average Price (Per Bbl)
 
Range (Per Bbl)
Period and Type of Contract
 
Volume (Bbl)
 
 
Low
 
High
Oil Swap Contracts:
 
 

 
 

 
 

 
 

2019
 
 

 
 

 
 

 
 

First Quarter
 
255,000

 
$
58.54

 
$
52.82

 
$
65.58

Second Quarter
 
855,000

 
58.72

 
52.82

 
65.58

Third Quarter
 
855,000

 
58.37

 
52.82

 
63.75

Fourth Quarter
 
855,000

 
58.37

 
52.82

 
63.75

2020
 


 


 


 


First Quarter
 
270,000

 
$
57.87

 
$
57.46

 
$
58.65

Second Quarter
 
270,000

 
57.87

 
57.46

 
58.65

Third Quarter
 
270,000

 
57.87

 
57.46

 
58.65

Fourth Quarter
 
270,000

 
57.87

 
57.46

 
58.65

 
 
 
 
Weighted Average
Floor Price (Per Bbl)
 
Weighted Average
Ceiling Price (Per Bbl)
Period and Type of Contract
 
Volume (Bbl)
 
 
Oil Collar Contracts:
 
 
 
 
 
 
2019
 
 
 
 
 
 
First Quarter
 
20,000

 
$
65.00
 
 
$
74.00
 
Second Quarter
 
60,000

 
65.00
 
 
74.00
 
Third Quarter
 
60,000

 
65.00
 
 
74.00
 
Fourth Quarter
 
60,000

 
65.00
 
 
74.00
 
2020
 
 
 
 
 
 
First Quarter
 
210,000

 
$
56.43
 
 
$
67.14
 
Second Quarter
 
210,000

 
56.43
 
 
67.14
 
Third Quarter
 
210,000

 
56.43
 
 
67.14
 
Fourth Quarter
 
210,000

 
56.43
 
 
67.14
 
The Partnership had the following open derivative contracts for natural gas as of March 31, 2019:
 
 

 
Weighted Average Price (Per MMBtu)
 
Range (Per MMBtu)
Period and Type of Contract
 
Volume (MMBtu)
 
 
Low
 
High
Natural Gas Swap Contracts:
 
 

 
 

 
 

 
 

2019
 
 

 
 

 
 

 
 

Second Quarter
 
14,520,000

 
$
2.96

 
$
2.81

 
$
3.20

Third Quarter
 
14,640,000

 
2.96

 
2.81

 
3.20

Fourth Quarter
 
14,640,000

 
2.96

 
2.81

 
3.20

2020
 
 
 
 
 
 
 
 
First Quarter
 
6,370,000

 
$
2.72

 
$
2.72

 
$
2.73

Second Quarter
 
6,370,000

 
2.72

 
2.72

 
2.73

Third Quarter
 
6,440,000

 
2.72

 
2.72

 
2.73

Fourth Quarter
 
6,440,000

 
2.72

 
2.72

 
2.73


11


BLACK STONE MINERALS, L.P. AND SUBSIDIARIES
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS


NOTE 6 — FAIR VALUE MEASUREMENTS
Fair value is defined as the amount at which an asset (or liability) could be bought (or incurred) or sold (or settled) in an orderly transaction between market participants at the measurement date. Further, ASC 820, Fair Value Measurement, establishes a framework for measuring fair value, establishes a fair value hierarchy based on the quality of inputs used to measure fair value, and includes certain disclosure requirements. Fair value estimates are based on either (i) actual market data or (ii) assumptions that other market participants would use in pricing an asset or liability, including estimates of risk.
ASC 820 establishes a three-level valuation hierarchy for disclosure of fair value measurements. The valuation hierarchy categorizes assets and liabilities measured at fair value into one of three different levels depending on the observability of the inputs employed in the measurement. The three levels are defined as follows:
Level 1—Unadjusted quoted prices for identical assets or liabilities in active markets.
Level 2—Quoted prices for similar assets or liabilities in non-active markets, and inputs that are observable for the asset or liability, either directly or indirectly, for substantially the full term of the financial instrument.
Level 3—Inputs that are unobservable and significant to the fair value measurement (including the Partnership’s own assumptions in determining fair value).
A financial instrument’s categorization within the valuation hierarchy is based upon the lowest level of input that is significant to the fair value measurement. The Partnership’s assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment and considers factors specific to the asset or liability. There were no transfers into, or out of, the three levels of the fair value hierarchy for the three months ended March 31, 2019 or the year ended December 31, 2018.
The carrying value of the Partnership's cash and cash equivalents, receivables, and payables approximate fair value due to the short-term nature of the instruments. The estimated carrying value of all debt as of March 31, 2019 and December 31, 2018 approximated the fair value due to variable market rates of interest. These debt fair values, which are Level 3 measurements, were estimated based on the Partnership’s incremental borrowing rates for similar types of borrowing arrangements, when quoted market prices were not available. The estimated fair values of the Partnership’s financial instruments are not necessarily indicative of the amounts that would be realized in a current market exchange.
Assets and Liabilities Measured at Fair Value on a Recurring Basis
The Partnership estimated the fair value of derivative instruments using the market approach via a model that uses inputs that are observable in the market or can be derived from, or corroborated by, observable data. See Note 5 – Commodity Derivative Financial Instruments for further discussion.

12


BLACK STONE MINERALS, L.P. AND SUBSIDIARIES
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS


The following table presents information about the Partnership’s assets and liabilities measured at fair value on a recurring basis: 
 
 
Fair Value Measurements Using
 
Effect of Counterparty Netting
 
Total
 
 
Level 1
 
Level 2
 
Level 3
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(in thousands)
As of March 31, 2019
 
 

 
 

 
 

 
 

 
 

Financial Assets
 
 

 
 

 
 

 
 

 
 

Commodity derivative instruments
 
$

 
$
16,659

 
$

 
$
(9,557
)
 
$
7,102

Financial Liabilities
 
 

 
 

 
 

 
 

 
 

Commodity derivative instruments
 
$

 
$
11,547

 
$

 
$
(9,557
)
 
$
1,990

As of December 31, 2018
 
 

 
 

 
 

 
 

 
 

Financial Assets
 
 

 
 

 
 

 
 

 
 

Commodity derivative instruments
 
$

 
$
50,264

 
$

 
$
(2,226
)
 
$
48,038

Financial Liabilities
 
 

 
 

 
 

 
 

 
 

Commodity derivative instruments
 
$

 
$
2,226

 
$

 
$
(2,226
)
 
$

Assets and Liabilities Measured at Fair Value on a Non-Recurring Basis
Nonfinancial assets and liabilities measured at fair value on a non-recurring basis include certain nonfinancial assets and liabilities as may be acquired in a business combination and measurements of oil and natural gas property values for assessment of impairment.
The determination of the fair values of proved and unproved properties acquired in business combinations are estimated by discounting projected future cash flows. The factors used to determine fair value include estimates of economic reserves, future operating and development costs, future commodity prices, timing of future production, and a risk-adjusted discount rate. The Partnership has designated these measurements as Level 3. The Partnership’s fair value assessments for recent acquisitions are included in Note 4 – Oil and Natural Gas Properties Acquisitions.
Oil and natural gas properties are measured at fair value on a non-recurring basis using the income approach when assessing for impairment. Proved and unproved oil and natural gas properties are reviewed for impairment when events and circumstances indicate a possible decline in the recoverability of the carrying value of those properties. When assessing producing properties for impairment, the Partnership compares the expected undiscounted projected future cash flows of the producing properties to the carrying amount of the producing properties to determine recoverability. When the carrying amount exceeds its estimated undiscounted future cash flows, the carrying amount is written down to its fair value, which is measured as the present value of the projected future cash flows of such properties. The factors used to determine fair value include estimates of proved reserves, future commodity prices, timing of future production, future capital expenditures, and a risk-adjusted discount rate.
The Partnership’s estimates of fair value have been determined at discrete points in time based on relevant market data. These estimates involve uncertainty and cannot be determined with precision. There were no significant changes in valuation techniques or related inputs as of March 31, 2019 or December 31, 2018.
There were no assets measured at fair value on a non-recurring basis, after initial recognition, for the three months ended March 31, 2019 and 2018.

13


BLACK STONE MINERALS, L.P. AND SUBSIDIARIES
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS


NOTE 7 — CREDIT FACILITY
The Partnership maintains a senior secured revolving credit agreement, as amended (the “Credit Facility”). The Credit Facility has an aggregate maximum credit amount of $1.0 billion and terminates on November 1, 2022. The commitment of the lenders equals the lesser of the aggregate maximum credit amount and the borrowing base. The amount of the borrowing base is redetermined semi-annually, usually in October and April, and is derived from the value of the Partnership’s oil and natural gas properties as determined by the lender syndicate using pricing assumptions that often differ from the current market for future prices. Effective May 4, 2018, the borrowing base redetermination increased the borrowing base from $550.0 million to $600.0 million and, effective October 31, 2018, the borrowing base was further increased to $675.0 million.
Outstanding borrowings under the Credit Facility bear interest at a floating rate elected by the Partnership equal to an alternative base rate (which is equal to the greatest of the Prime Rate, the Federal Funds effective rate plus 0.50%, or 1-month LIBOR plus 1.00%) or LIBOR, in each case, plus the applicable margin. Prior to October 31, 2018, the applicable margin ranged from 1.00% to 2.00% in the case of the alternative base rate and from 2.00% to 3.00% in the case of LIBOR, depending on the borrowings outstanding in relation to the borrowing base. Effective October 31, 2018, the applicable margin for the alternative base rate was reduced to between 0.75% and 1.75% and the applicable margin for LIBOR was reduced to between 1.75% and 2.75%.
The weighted-average interest rate of the Credit Facility was 4.75% and 4.76% as of March 31, 2019 and December 31, 2018, respectively. Accrued interest is payable at the end of each calendar quarter or at the end of each interest period, unless the interest period is longer than 90 days, in which case interest is payable at the end of every 90-day period. In addition, a commitment fee is payable at the end of each calendar quarter based on either a rate of 0.375% if the borrowing base utilization percentage is less than 50%, or 0.500% if the borrowing base utilization percentage is equal to or greater than 50%. The Credit Facility is secured by substantially all of the Partnership’s oil and natural gas production and assets.
The Credit Facility contains various limitations on future borrowings, leases, hedging, and sales of assets. Additionally, the Credit Facility requires the Partnership to maintain a current ratio of not less than 1.0:1.0 and a ratio of total debt to EBITDAX (Earnings before Interest, Taxes, Depreciation, Amortization, and Exploration) of not more than 3.5:1.0. As of March 31, 2019, the Partnership was in compliance with all financial covenants in the Credit Facility.
The aggregate principal balance outstanding was $435.0 million and $410.0 million at March 31, 2019 and December 31, 2018, respectively. The unused portion of the available borrowings under the Credit Facility were $240.0 million and $265.0 million at March 31, 2019 and December 31, 2018, respectively.
NOTE 8 — COMMITMENTS AND CONTINGENCIES
Environmental Matters
The Partnership’s business includes activities that are subject to U.S. federal, state, and local environmental regulations with regard to air, land, and water quality and other environmental matters.
The Partnership does not consider the potential remediation costs that could result from issues identified in any environmental site assessments to be significant to the consolidated financial statements, and no provision for potential remediation costs has been recorded.
Put Option Related to Noble Acquisition
By acquiring 100% of the issued and outstanding securities of Samedan Royalty, LLC, now NAMP Holdings, LLC, on November 28, 2017 from Noble Energy US Holdings, LLC, the Partnership acquired a 100% interest in Comin-Temin, LLC, now NAMP GP, LLC ("Holdings"), Comin 1989 Partnership LLLP, now NAMP 1, LP ("Comin"), and Temin 1987 Partnership LLLP, now NAMP 2, LP ("Temin"). Pursuant to certain co-ownership agreements, various co-owners hold undivided beneficial ownership interests in 45.33% and 42.63% of the minerals interests held of record by Holdings and Temin, respectively. Based on the terms of the co-ownership agreements, the co-owners each have an unconditional option to require Comin or Temin, as applicable, to purchase their beneficial ownership interest in the mineral interests held of record by Holdings or Temin, as applicable, at any time within 30 days of receiving such repurchase notice. The purchase price of the beneficial ownership interest shall be based on an evaluation performed by Comin or Temin, as applicable, in good faith. As of March 31, 2019, the

14


BLACK STONE MINERALS, L.P. AND SUBSIDIARIES
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS


Partnership had not received notice from any co-owner to exercise their repurchase option, and as such, no liability was recorded.
Litigation
From time to time, the Partnership is involved in legal actions and claims arising in the ordinary course of business. The Partnership believes existing claims as of March 31, 2019 will be resolved without material adverse effect on the Partnership’s financial condition or operations. 
NOTE 9 — INCENTIVE COMPENSATION
The table below summarizes incentive compensation expense recorded in general and administrative expenses in the consolidated statements of operations for the three months ended March 31, 2019 and 2018:
 
 
Three Months Ended March 31,
 
 
2019
 
2018
 
 
 
 
 
 
 
(in thousands)
Cash—short and long-term incentive plans
 
$
1,772

 
$
1,634

Equity-based compensation—restricted common and subordinated units
 
3,019

 
3,405

Equity-based compensation—restricted performance units
 
5,620

 
2,242

Board of Directors incentive plan
 
585

 
579

 Total incentive compensation expense
 
$
10,996

 
$
7,860

 
NOTE 10 — PREFERRED UNITS
Series A Redeemable Preferred Units
As of March 31, 2019 and December 31, 2018, there were no Series A redeemable preferred units outstanding. The Series A redeemable preferred units were entitled to an annual distribution of 10% of the outstanding funded capital of the Series A redeemable preferred units, payable on a quarterly basis in arrears.
The Series A redeemable preferred units were convertible into common and subordinated units at any time at the option of the Series A redeemable preferred unitholders. The Series A redeemable preferred units had an adjusted conversion price of $14.2683 and an adjusted conversion rate of 30.3431 common units and 39.7427 subordinated units per redeemable preferred unit.
The Series A redeemable preferred unitholders had the option to elect to have the Partnership redeem, at face value, all remaining Series A redeemable preferred units, effective as of December 31, 2017, plus any accrued and unpaid distributions.  All Series A redeemable preferred units not redeemed by March 31, 2018 automatically converted to common and subordinated units effective as of January 1, 2018 or as soon as practicable thereafter.
For the three months ended March 31, 2018, 2,115 Series A redeemable preferred units were redeemed for $2.1 million, including accrued unpaid yield, and 24,248 Series A redeemable preferred units totaling $24.2 million were converted into 735,758 common units and 963,681 subordinated units as a result of the mandatory conversion subsequent to December 31, 2017.
Series B Cumulative Convertible Preferred Units
On November 28, 2017, the Partnership issued and sold in a private placement 14,711,219 Series B cumulative convertible preferred units representing limited partner interests in the Partnership for a cash purchase price of $20.3926 per Series B cumulative convertible preferred unit, resulting in total proceeds of approximately $300.0 million.
The Series B cumulative convertible preferred units are entitled to an annual distribution of 7%, payable on a quarterly basis in arrears. For the eight quarters consisting of the quarter in respect of which the initial distribution is paid and the seven full quarters thereafter, the quarterly distribution may be paid, at the sole option of the Partnership, (i) in-kind in the form of

15


BLACK STONE MINERALS, L.P. AND SUBSIDIARIES
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS


additional Series B cumulative convertible preferred units (the "Series B PIK Units"), (ii) in cash, or (iii) in a combination of Series B PIK Units and cash. Beginning with the ninth quarter, all Series B cumulative convertible preferred unit distributions shall be paid in cash. The number of Series B PIK Units to be issued, if any, shall equal the quotient of the Series B cumulative convertible preferred unit distribution amount (or portion thereof) divided by the Series B cumulative convertible preferred unit purchase price of $20.3926.
The Series B cumulative convertible preferred units are convertible into common units of the Partnership on November 29, 2019 and once per quarter thereafter. At such time, the Series B cumulative convertible preferred units may be converted by each holder at its option, in whole or in part, into common units on a one-for-one basis at the purchase price of $20.3926, adjusted to give effect to any accrued but unpaid accumulated distributions on the applicable Series B cumulative convertible preferred units through the most recent declaration date. However, the Partnership shall not be obligated to honor any request for such conversion if such request does not involve an underlying value of common units of at least $10.0 million based on the closing trading price of common units on the trading day immediately preceding the conversion notice date, or such lesser amount to the extent such exercise covers all of a holder's Series B cumulative convertible preferred units.
The Series B cumulative convertible preferred units had a carrying value of $298.4 million and $298.4 million, including accrued distributions of $5.3 million and $5.3 million, as of March 31, 2019 and December 31, 2018, respectively. The Series B cumulative convertible preferred units are classified as mezzanine equity on the consolidated balance sheets since certain provisions of redemption are outside the control of the Partnership.
NOTE 11 — EARNINGS PER UNIT    
The Partnership applies the two-class method for purposes of calculating earnings per unit (“EPU”). The holders of the Partnership’s restricted common and subordinated units have all the rights of a unitholder, including non-forfeitable distribution rights. As participating securities, the restricted common and subordinated units are included in the calculation of basic earnings per unit. For the periods presented, the amount of earnings allocated to these participating units was not material.
Net income (loss) attributable to the Partnership is allocated to the Partnership’s general partner and the common and subordinated unitholders in proportion to their pro rata ownership after giving effect to distributions, if any, declared during the period.
The Partnership’s restricted performance unit awards are contingently issuable units that are considered in the calculation of diluted EPU. The Partnership assesses the number of units that would be issuable, if any, under the terms of the arrangement if the end of the reporting period were the end of the contingency period. At March 31, 2019 and 2018, there were 0.6 million and 0.1 million units, respectively, related to the Partnership’s restricted performance unit awards included in the calculation of diluted EPU.

16


BLACK STONE MINERALS, L.P. AND SUBSIDIARIES
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS


The following table sets forth the computation of basic and diluted earnings per common and subordinated unit:
 
 
Three Months Ended March 31,
 
 
2019
 
2018
 
 
 
 
 
 
 
(in thousands, except per unit amounts)
NET INCOME (LOSS)
 
$
9,017

 
$
41,957

Net (income) loss attributable to noncontrolling interests
 

 
(27
)
Distributions on Series A redeemable preferred units
 

 
(25
)
Distributions on Series B cumulative convertible preferred units
 
(5,250
)
 
(5,250
)
NET INCOME (LOSS) ATTRIBUTABLE TO THE GENERAL PARTNER AND COMMON AND SUBORDINATED UNITS
 
3,767

 
36,655

ALLOCATION OF NET INCOME (LOSS):
 
 
 
 

General partner interest
 
$

 
$

Common units
 
1,905

 
24,329

Subordinated units
 
1,862

 
12,326

 
 
$
3,767

 
$
36,655

Weighted average common units outstanding:
 
 
 
 
Weighted average common units outstanding (basic)
 
109,420

 
103,774

Effect of dilutive securities
 
615

 
64

Weighted average common units outstanding (diluted)
 
110,035

 
103,838

Weighted average subordinated units outstanding:
 
 
 
 
Weighted average subordinated units outstanding (basic)
 
96,329

 
95,395

Effect of dilutive securities
 

 

Weighted average subordinated units outstanding (diluted)
 
96,329

 
95,395

NET INCOME (LOSS) ATTRIBUTABLE TO LIMITED PARTNERS PER COMMON AND SUBORDINATED UNIT:
 
 

 
 

Per common unit (basic)
 
$
0.02

 
$
0.23

Per subordinated unit (basic)
 
0.02

 
0.13

Per common unit (diluted)
 
0.02

 
0.23

Per subordinated unit (diluted)
 
0.02

 
0.13


17


BLACK STONE MINERALS, L.P. AND SUBSIDIARIES
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS


The following units of potentially dilutive securities were excluded from the computation of diluted weighted average units outstanding because their inclusion would be anti-dilutive:
 
 
Three Months Ended March 31,
 
 
2019
 
2018
 
 
 
 
 
 
 
(in thousands)
Potentially dilutive securities (common units):
 
 
 
 
Series A redeemable preferred units on an as-converted basis
 

 
181

Series B cumulative convertible preferred units on an as-converted basis
 
14,969

 
15,063

 
 
14,969

 
15,244

Potentially dilutive securities (subordinated units):
 
 
 
 
Series A redeemable preferred units on an as-converted basis
 

 
247

 
 

 
247

NOTE 12 — COMMON AND SUBORDINATED UNITS

Common and Subordinated Units

The common units and subordinated units represent limited partner interests in the Partnership. The partnership agreement restricts unitholders’ voting rights by providing that any units held by a person or group that owns 15% or more of any class of units then outstanding other than the limited partners in Black Stone Minerals Company, L.P. prior to the initial public offering of BSM, their transferees, persons who acquired such units with the prior approval of the board of directors of the Partnership's general partner (the "Board"), holders of Series B cumulative convertible preferred units in connection with any vote, consent or approval of the Series B cumulative convertible preferred units as a separate class, and persons who own 15% or more of any class as a result of any redemption or purchase of any other person's units or similar action by the Partnership or any conversion of the Series B cumulative convertible preferred units at the Partnership's option or in connection with a change of control may not vote on any matter.

The holders of common units and subordinated units are entitled to participate in distributions and exercise the rights and privileges provided to limited partners holding common units and subordinated units under the partnership agreement.

The partnership agreement generally provides that any distributions will be paid each quarter during the subordination period (as defined in the partnership agreement) in the following manner:

first, to the holders of the Series B cumulative convertible preferred units in an amount equal to 7% per annum, subject to certain adjustments;
second, to the holders of common units, until each common unit has received the applicable minimum quarterly distribution plus any arrearages from prior quarters; and
third, to the holders of subordinated units, until each subordinated unit has received the applicable minimum quarterly distribution.

If the distributions to common and subordinated unitholders exceed the applicable minimum quarterly distribution per unit, then such excess amounts will be distributed pro rata on the common and subordinated units as if they were a single class. The priority right of the common unitholders will cease to exist upon full conversion of the subordinated units to common units.

18


BLACK STONE MINERALS, L.P. AND SUBSIDIARIES
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS


The following table provides information about the Partnership's per unit distributions to common and subordinated unitholders:
 
 
Three Months Ended March 31,
 
 
2019
 
2018
DISTRIBUTIONS DECLARED AND PAID:
 
 
 
 
Per common unit
 
$
0.3700

 
$
0.3125

Per subordinated unit
 
0.3700

 
0.2088


End of the Subordination Period
The subordination period under the partnership agreement will end on the first business day after the Partnership has earned and paid an aggregate amount of at least $1.35 (the annualized minimum quarterly distribution applicable for quarterly periods ending March 31, 2019 and thereafter) multiplied by the total number of outstanding common and subordinated units for a period of four consecutive, non-overlapping quarters ending on or after March 31, 2019, and there are no outstanding arrearages on the common units. When the subordination period ends as a result of the Partnership having met the test described above, all subordinated units will convert into common units on a one-to-one basis, and common units will thereafter no longer be entitled to arrearages.

Common Unit Repurchase Program

On November 5, 2018, the Board authorized the repurchase of up to $75.0 million in common units. The repurchase program authorizes the Partnership to make repurchases on a discretionary basis as determined by management, subject to market conditions, applicable legal requirements, available liquidity, and other appropriate factors. The Partnership made no repurchases under this program for the three months ended March 31, 2019. The repurchase program is funded from the Partnership's cash on hand or availability on the Credit Facility. Any repurchased units are canceled.

At-The-Market Offering Program

On May 26, 2017, the Partnership commenced an at-the-market offering program (the “ATM Program”) and in connection therewith entered into an Equity Distribution Agreement with Wells Fargo Securities, LLC, Merrill Lynch, Pierce, Fenner & Smith Incorporated, and UBS Securities LLC, as Sales Agents (each a “Sales Agent” and collectively the “Sales Agents”). Pursuant to the terms of the ATM Program, the Partnership may sell, from time to time through the Sales Agents, the Partnership’s common units representing limited partner interests having an aggregate offering amount of up to $100,000,000. Sales of common units, if any, may be made in negotiated transactions or transactions that are deemed to be “at the market” offerings as defined in Rule 415 under the Securities Act of 1933, as amended (the “Securities Act”), including sales made directly on the New York Stock Exchange or sales made to or through a market maker other than on an exchange.
Under the terms of the ATM Program, the Partnership may also sell common units to one or more of the Sales Agents as principal for its own account at a price to be agreed upon at the time of sale. Any sale of common units to a Sales Agent as principal would be pursuant to the terms of a separate agreement between the Partnership and such Sales Agent.
The Partnership intends to use the net proceeds from any sales pursuant to the ATM Program, after deducting the Sales Agents’ commissions and the Partnership’s offering expenses, for general partnership purposes, which may include, among other things, repayment of indebtedness outstanding under the Partnership’s Credit Facility.
Common units sold pursuant to the Equity Distribution Agreement are offered and sold pursuant to the Partnership’s existing effective shelf-registration statement on Form S-3 (File No. 333-215857), which was declared effective by the SEC on February 8, 2017.
The Equity Distribution Agreement contains customary representations, warranties and agreements, indemnification obligations, including for liabilities under the Securities Act, other obligations of the parties and termination provisions.

19


BLACK STONE MINERALS, L.P. AND SUBSIDIARIES
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS


For the three months ended March 31, 2019, the Partnership sold no common units under the ATM Program. For the three months ended March 31, 2018, the Partnership sold 8,204 common units under the ATM program for net proceeds of $0.1 million. As of March 31, 2019, the Partnership has raised net proceeds of $73.0 million under the ATM Program.
NOTE 13 — SUBSEQUENT EVENTS    
On April 25, 2019, the Board approved a distribution for the three months ended March 31, 2019 of $0.37 per common unit and $0.37 per subordinated unit. Distributions will be payable on May 23, 2019 to unitholders of record at the close of business on May 16, 2019. The Board also confirmed and approved that, upon payment of the distribution for the three months ended March 31, 2019, the tests required for conversion of all of the outstanding subordinated units into common units on a one-for-one basis will be met. Accordingly, on the first business day following the payment of the distribution described, the Partnership's 96,328,836 subordinated units will convert into 96,328,836 common units.

20


Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our unaudited consolidated financial statements and notes thereto presented in this Quarterly Report on Form 10-Q, as well as our audited consolidated financial statements and notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2018. This discussion and analysis contains forward-looking statements that involve risks, uncertainties, and assumptions. Actual results may differ materially from those anticipated in these forward-looking statements as a result of a number of factors, including those set forth under “Cautionary Note Regarding Forward-Looking Statements” and “Part II, Item 1A. Risk Factors.”
Cautionary Note Regarding Forward-Looking Statements
Certain statements and information in this Quarterly Report on Form 10-Q may constitute “forward-looking statements.”  The words “believe,” “expect,” “anticipate,” “plan,” “intend,” “foresee,” “should,” “would,” “could,” or other similar expressions are intended to identify forward-looking statements, which are generally not historical in nature.  These forward-looking statements are based on our current expectations and beliefs concerning future developments and their potential effect on us.  While management believes that these forward-looking statements are reasonable as and when made, there can be no assurance that future developments affecting us will be those that we anticipate.  All comments concerning our expectations for future revenues and operating results are based on our forecasts for our existing operations and do not include the potential impact of any future acquisitions.  Our forward-looking statements involve significant risks and uncertainties (some of which are beyond our control) and assumptions that could cause actual results to differ materially from our historical experience and our present expectations or projections.  Important factors that could cause actual results to differ materially from those in the forward-looking statements include, but are not limited to, those summarized below:
our ability to execute our business strategies;

the volatility of realized oil and natural gas prices;

the level of production on our properties;

the overall supply and demand for oil and natural gas, regional supply and demand factors, delays, or interruptions of production;

our ability to replace our oil and natural gas reserves;

our ability to identify, complete, and integrate acquisitions;

general economic, business, or industry conditions;

competition in the oil and natural gas industry;

the ability of our operators to obtain capital or financing needed for development and exploration operations;

title defects in the properties in which we invest;

the availability or cost of rigs, equipment, raw materials, supplies, oilfield services, or personnel;

restrictions on the use of water for hydraulic fracturing;

the availability of pipeline capacity and transportation facilities;

the ability of our operators to comply with applicable governmental laws and regulations and to obtain permits and governmental approvals;

federal and state legislative and regulatory initiatives relating to hydraulic fracturing;

future operating results;

future cash flows and liquidity, including our ability to generate sufficient cash to pay quarterly distributions;

21



exploration and development drilling prospects, inventories, projects, and programs;

operating hazards faced by our operators;

the ability of our operators to keep pace with technological advancements; and 

certain factors discussed elsewhere in this filing.
For additional information regarding known material factors that could cause our actual results to differ from our projected results, please see “Risk Factors” in our Annual Report on Form 10-K.
Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date hereof.  We undertake no obligation to publicly update or revise any forward-looking statements after the date they are made, whether as a result of new information, future events, or otherwise.
Overview
We are one of the largest owners and managers of oil and natural gas mineral interests in the United States. Our principal business is maximizing the value of our existing mineral and royalty assets through active management and expanding our asset base through acquisitions of additional mineral and royalty interests. We maximize value through marketing our mineral assets for lease, creatively structuring the terms on those leases to encourage and accelerate drilling activity, and selectively participating alongside our lessees on a working interest basis. Our primary business objective is to grow our reserves, production, and cash generated from operations over the long term, while paying, to the extent practicable, a growing quarterly distribution to our unitholders.
As of March 31, 2019, our mineral and royalty interests were located in 41 states in the continental United States, including all of the major onshore producing basins. These non-cost-bearing interests, which we refer to collectively as our "mineral and royalty interests," include ownership in over 60,000 producing wells. We also own non-operated working interests, a significant portion of which are on our positions where we also have a mineral and royalty interest. We recognize oil and natural gas revenue from our mineral and royalty and non-operated working interests in producing wells when control of the oil and natural gas produced is transferred to the customer and collectability of the sales price is reasonably assured. Our other sources of revenue include mineral lease bonus and delay rentals, which are recognized as revenue according to the terms of the lease agreements.
Recent Developments
Acquisitions
In the first quarter of 2019, we acquired mineral and royalty interests primarily in the Permian Basin and in East Texas for aggregate consideration of $20.0 million in cash and $0.9 million in our common units. Additional information regarding acquisitions is contained in Note 4 – Oil and Natural Gas Properties Acquisitions to our unaudited consolidated financial statements included elsewhere in this Quarterly Report on Form 10-Q for further discussion.
PepperJack Prospect
We drilled the PepperJack A#1 well targeting the Lower Wilcox formation within our PepperJack prospect in Hardin and Liberty counties, Texas during the fourth quarter of 2017 and first quarter of 2018.
On September 21, 2018, we entered into an exploration agreement with a consortium of private exploration and production companies (the “Development Partners”) to further delineate and develop the Pepperjack prospect. As part of the agreement, we assigned 75% of our working interest in the PepperJack A#1 well and acreage in the associated unit to the Development Partners and transferred our status as the operator of record. We received proceeds of $6.4 million for the assignment, which represented a reimbursement for 100% of the drilling costs and associated acreage, proceeds of $1.0 million for an option covering our mineral interests and leases in the PepperJack prospect area, and an overriding royalty interest in the PepperJack prospect area. The Development Partners completed the PepperJack A#1 well in April 2019 and data is being collected to determine viability for economic development of the prospect.

22


End of the Subordination Period
The subordination period under the partnership agreement will end on the first business day after we have earned and paid an aggregate amount of at least $1.35 (the annualized minimum quarterly distribution applicable for quarterly periods ending March 31, 2019 and thereafter) multiplied by the total number of outstanding common and subordinated units for a period of four consecutive, non-overlapping quarters ending on or after March 31, 2019, and there are no outstanding arrearages on the common units. This test will be met upon the payment of the current quarter distribution which is payable on May 23, 2019. When the subordination period ends as a result of us having met the test described above, all subordinated units will convert into common units on a one-to-one basis, and common units will thereafter no longer be entitled to arrearages.
Common Unit Repurchase Program

On November 5, 2018, the Board authorized the repurchase of up to $75.0 million in common units. The repurchase program authorizes us to make repurchases on a discretionary basis as determined by management, subject to market conditions, applicable legal requirements, available liquidity, and other appropriate factors. We have made no repurchases under this program for the three months ended March 31, 2019. The repurchase program is funded from our cash on hand or availability on the Credit Facility. Any repurchased units are canceled.
Business Environment
The information presented below is designed to give a broad overview of the oil and natural gas business environment as it affects us.

Commodity Prices and Demand
Oil and natural gas prices have been historically volatile based upon the dynamics of supply and demand. The U.S. Energy Information Administration ("EIA") forecasts that the WTI spot oil price will average $58.80 per Bbl in 2019 and $58.00 per Bbl in 2020 and that the Henry Hub spot natural gas prices will average $2.82 per MMBtu in 2019 and $2.77 per MMBtu in 2020.
To manage the variability in cash flows associated with the projected sale of our oil and natural gas production, we use various derivative instruments, which have recently consisted of fixed-price swap contracts and costless collar contracts.
The following table reflects commodity prices at the end of each quarter presented:
 
 
2019
 
2018
Benchmark Prices1
 
First Quarter
 
First Quarter
WTI spot crude oil ($/Bbl)1
 
$
60.19

 
$
64.87

Henry Hub spot natural gas ($/MMBtu)1
 
$
2.73

 
$
2.81

1    Source: EIA

23


Rig Count
As we are not the operator of record on any producing properties, drilling on our acreage is dependent upon the exploration and production companies that lease our acreage. In addition to drilling plans that we seek from our operators, we also monitor rig counts in an effort to identify existing and future leasing and drilling activity on our acreage.
The following table shows the rig count at the close of each quarter presented:
 
 
2019
2018
U.S. Rotary Rig Count1
 
First Quarter
 
First Quarter
Oil
 
816

 
797

Natural gas
 
190

 
194

Other
 

 
2

Total
 
1,006

 
993

1 
Source: Baker Hughes Incorporated
Natural Gas Storage
A substantial portion of our revenue is derived from sales of oil production attributable to our interests; however, the majority of our production is natural gas. Natural gas prices are significantly influenced by storage levels throughout the year. Accordingly, we monitor the natural gas storage reports regularly in the evaluation of our business and its outlook.
Historically, natural gas supply and demand fluctuates on a seasonal basis. From April to October, when the weather is warmer and natural gas demand is lower, natural gas storage levels generally increase. From November to March, storage levels typically decline as utility companies draw natural gas from storage to meet increased heating demand due to colder weather. In order to maintain sufficient storage levels for increased seasonal demand, a portion of natural gas production during the summer months must be used for storage injection. The portion of production used for storage varies from year to year depending on the demand from the previous winter and the demand for electricity used for cooling during the summer months. The EIA estimates that natural gas inventories declined to 1.2 trillion cubic feet on March 31, 2019, the lowest level since 2014. However, the EIA expects steadily rising natural gas production to contribute to inventory builds outpacing the previous five-year average during the 2019 injection season. The EIA forecasts natural gas inventories will reach 3.7 trillion cubic feet on October 31, 2019, which is 1% lower than the previous five-year average compared with inventory levels that were 30% lower than the previous five-year average on March 31, 2019.
The following table shows natural gas storage volumes by region at the end of each quarter presented:
 
 
2019
 
2018
Region1
 
First Quarter
 
First Quarter
 
 
 
 
 
 
 
 
East
 
210

 
229

Midwest
 
241

 
266

Mountain
 
64

 
87

Pacific
 
113

 
166

South Central
 
502

 
606

Total
 
1,130

 
1,354

1 
Source: EIA

24


How We Evaluate Our Operations
We use a variety of operational and financial measures to assess our performance. Among the measures considered by management are the following:
volumes of oil and natural gas produced;
commodity prices including the effect of derivative instruments; and
Adjusted EBITDA and distributable cash flow.
Volumes of Oil and Natural Gas Produced
In order to track and assess the performance of our assets, we monitor and analyze our production volumes from the various basins and plays that constitute our extensive asset base. We also regularly compare projected volumes to actual reported volumes and investigate unexpected variances.
Commodity Prices
Factors Affecting the Sales Price of Oil and Natural Gas
The prices we receive for oil, natural gas, and natural gas liquids (“NGLs”) vary by geographical area. The relative prices of these products are determined by the factors affecting global and regional supply and demand dynamics, such as economic conditions, production levels, availability of transportation, weather cycles, and other factors. In addition, realized prices are influenced by product quality and proximity to consuming and refining markets. Any differences between realized prices and NYMEX prices are referred to as differentials. All our production is derived from properties located in the United States.
Oil. The substantial majority of our oil production is sold at prevailing market prices, which fluctuate in response to many factors that are outside of our control. NYMEX light sweet crude oil, commonly referred to as WTI, is the prevailing domestic oil pricing index. The majority of our oil production is priced at the prevailing market price with the final realized price affected by both quality and location differentials.
The chemical composition of oil plays an important role in its refining and subsequent sale as petroleum products.  As a result, variations in chemical composition relative to the benchmark oil, usually WTI, will result in price adjustments, which are often referred to as quality differentials. The characteristics that most significantly affect quality differentials include the density of the oil, as characterized by its American Petroleum Institute (“API”) gravity, and the presence and concentration of impurities, such as sulfur.
Location differentials generally result from transportation costs based on the produced oil’s proximity to consuming and refining markets and major trading points.
Natural Gas. The NYMEX price quoted at Henry Hub is a widely used benchmark for the pricing of natural gas in the United States. The actual volumetric prices realized from the sale of natural gas differ from the quoted NYMEX price as a result of quality and location differentials. 
Quality differentials result from the heating value of natural gas measured in Btus and the presence of impurities, such as hydrogen sulfide, carbon dioxide, and nitrogen. Natural gas containing ethane and heavier hydrocarbons has a higher Btu value and will realize a higher volumetric price than natural gas which is predominantly methane, which has a lower Btu value. Natural gas with a higher concentration of impurities will realize a lower volumetric price due to the presence of the impurities in the natural gas when sold or the cost of treating the natural gas to meet pipeline quality specifications.
Natural gas, which currently has a limited global transportation system, is subject to price variances based on local supply and demand conditions and the cost to transport natural gas to end user markets.
Hedging
We enter into derivative instruments to partially mitigate the impact of commodity price volatility on our cash generated from operations. From time to time, such instruments may include variable-to-fixed-price swaps, fixed-price contracts, costless

25


collars, and other contractual arrangements. The impact of these derivative instruments could affect the amount of revenue we ultimately realize.
Our open derivative contracts consist of fixed-price swap contracts and costless collar contracts. Under fixed-price swap contracts, a counterparty is required to make a payment to us if the settlement price is less than the swap strike price. Conversely, we are required to make a payment to the counterparty if the settlement price is greater than the swap strike price. Our costless collar contracts contain a fixed floor price and a fixed ceiling price. If the market price exceeds the fixed ceiling price, we receive the fixed ceiling price from the counterparty and we pay the market price. If the market price is below the fixed floor price, we receive the fixed floor price and we pay the market price. If the market price is between the fixed floor and fixed ceiling price, no payments are due from either party. If we have multiple contracts outstanding with a single counterparty, unless restricted by our agreement, we will net settle the contract payments.
We may employ contractual arrangements other than fixed-price swap contracts and costless collar contracts in the future to mitigate the impact of price fluctuations. If commodity prices decline in the future, our hedging contracts will partially mitigate the effect of lower prices on our future revenue. Our open oil and natural gas derivative contracts as of March 31, 2019 are detailed in Note 5 – Commodity Derivative Financial Instruments to our unaudited consolidated financial statements included elsewhere in this Quarterly Report on Form 10-Q.
Pursuant to the terms of our Credit Facility, we are allowed to hedge certain percentages of expected future monthly production volumes equal to the lesser of (i) internally forecasted production and (ii) the average of reported production for the most recent three months.
We are allowed to hedge up to 90% of such volumes for the first 24 months, 70% for months 25 through 36, and 50% for months 37 through 48. As of March 31, 2019, we have hedged 92% and 48% of our available oil and condensate hedge volumes for 2019 and 2020, respectively.  Also, we have hedged 92% and 38% of our available natural gas hedge volumes for 2019 and 2020, respectively.
We intend to continuously monitor the production from our assets and the commodity price environment, and will, from time to time, add additional hedges within the percentages described above related to such production for the following 12 to 30 months. We do not enter into derivative instruments for speculative purposes.
Non-GAAP Financial Measures
Adjusted EBITDA and distributable cash flow are supplemental non-GAAP financial measures used by our management and external users of our financial statements such as investors, research analysts, and others, to assess the financial performance of our assets and our ability to sustain distributions over the long term without regard to financing methods, capital structure, or historical cost basis.
We define Adjusted EBITDA as net income (loss) before interest expense, income taxes, and depreciation, depletion, and amortization adjusted for impairment of oil and natural gas properties, accretion of asset retirement obligations, unrealized gains and losses on commodity derivative instruments, and non-cash equity-based compensation. We define distributable cash flow as Adjusted EBITDA plus or minus amounts for certain non-cash operating activities, estimated replacement capital expenditures, cash interest expense, and distributions to noncontrolling interests and preferred unitholders.
Adjusted EBITDA and distributable cash flow should not be considered an alternative to, or more meaningful than, net income (loss), income (loss) from operations, cash flows from operating activities, or any other measure of financial performance presented in accordance with GAAP in the United States as measures of our financial performance.
Adjusted EBITDA and distributable cash flow have important limitations as analytical tools because they exclude some but not all items that affect net income (loss), the most directly comparable GAAP financial measure. Our computation of Adjusted EBITDA and distributable cash flow may differ from computations of similarly titled measures of other companies.

26


The following table presents a reconciliation of net income (loss), the most directly comparable GAAP financial measure, to Adjusted EBITDA and distributable cash flow for the periods indicated:
 
 
Three Months Ended
March 31,
 
 
2019
 
2018
 
 
 
 
 
 
 
(in thousands)
Net income (loss)
 
$
9,017

 
$
41,957

Adjustments to reconcile to Adjusted EBITDA:
 
 
 
 
Depreciation, depletion, and amortization
 
27,833

 
28,570

Interest expense
 
5,525

 
4,521

Income tax expense
 
131

 
1,507

Accretion of asset retirement obligations
 
277

 
269

Equity–based compensation
 
9,223

 
6,226

Unrealized (gain) loss on commodity derivative instruments
 
42,926

 
11,958

Adjusted EBITDA
 
94,932

 
95,008

Adjustments to reconcile to distributable cash flow:
 
 
 
 
Change in deferred revenue
 
(304
)
 
1,303

Cash interest expense
 
(5,269
)
 
(4,316
)
(Gain) loss on sale of assets, net
 

 
(2
)
Estimated replacement capital expenditures1
 
(2,750
)
 
(3,250
)
Cash paid to noncontrolling interests


 
(52
)
Preferred unit distributions
 
(5,250
)
 
(5,275
)
Distributable cash flow
 
$
81,359

 
$
83,416

1 
The Board established a replacement capital expenditure estimate of $13.0 million for the period of April 1, 2017 to March 31, 2018 and $11.0 million for the period of April 1, 2018 to March 31, 2019.


27


Results of Operations
Three Months Ended March 31, 2019 Compared to Three Months Ended March 31, 2018
The following table shows our production, revenues, pricing, and expenses for the periods presented:
 
 
Three Months Ended March 31,
 
 
2019
 
2018
 
Variance
 
 
 
 
 
 
 
 
 
 
 
(Dollars in thousands, except for realized prices)
Production:
 
 

 
 

 
 

 
 

Oil and condensate (MBbls)
 
1,108


1,190

 
(82
)
 
(6.9
)%
Natural gas (MMcf)1
 
18,615


15,742

 
2,873

 
18.3
 %
Equivalents (MBoe)
 
4,211


3,814

 
397

 
10.4
 %
Equivalents/day (MBoe)
 
46.8

 
42.4

 
4.4

 
10.4
 %
Revenue:
 
 
 
 
 
 
 
 
Oil and condensate sales
 
$
57,704

 
$
72,983

 
$
(15,279
)
 
(20.9
)%
Natural gas and natural gas liquids sales1
 
61,640

 
53,245

 
8,395

 
15.8
 %
Lease bonus and other income
 
5,645

 
4,599

 
1,046

 
22.7
 %
Revenue from contracts with customers
 
124,989

 
130,827

 
(5,838
)
 
(4.5
)%
Gain (loss) on commodity derivative instruments
 
(41,183
)
 
(16,333
)
 
(24,850
)
 
152.1
 %
Total revenue
 
$
83,806


$
114,494

 
$
(30,688
)
 
(26.8
)%
Realized prices, without derivatives:
 
 


 

 
 
 
 
Oil and condensate ($/Bbl)
 
$
52.08


$
61.33

 
$
(9.25
)
 
(15.1
)%
Natural gas ($/Mcf)1
 
3.31


3.38

 
(0.07
)
 
(2.1
)%
Equivalents ($/Boe)
 
$
28.34


$
33.10

 
$
(4.76
)
 
(14.4
)%
Operating expenses:
 
 


 

 
 
 
 
Lease operating expense
 
$
5,292


$
4,248

 
$
1,044

 
24.6
 %
Production costs and ad valorem taxes
 
14,592


14,925

 
(333
)
 
(2.2
)%
Exploration expense
 
4


3

 
1

 
NM2

Depreciation, depletion, and amortization
 
27,833


28,570

 
(737
)
 
(2.6
)%
General and administrative

21,214


18,521


2,693


14.5
 %
1  
As a mineral and royalty interest owner, we are often provided insufficient and inconsistent data on NGL volumes by our operators. As a result, we are unable to reliably determine the total volumes of NGLs associated with the production of natural gas on our acreage. Accordingly, no NGL volumes are included in our reported production; however, revenue attributable to NGLs is included in our natural gas revenue and our calculation of realized prices for natural gas.
2 
Not meaningful
Revenue
Total revenue for the quarter ended March 31, 2019 decreased compared to the quarter ended March 31, 2018. The decrease in total revenue from the corresponding prior period is primarily due to an increased loss from our commodity derivative instruments, decreased oil and condensate production volumes, lower realized oil and condensate commodity prices, and certain adjustments related to our year-end receivable balances which lowered reported production by approximately 2.0 MBoe/d and reduced revenue for the first quarter by approximately $6.2 million. The overall decrease in total revenue was partially offset by an increase in natural gas and NGL sales as a result of increased natural gas production volumes.
Oil and condensate sales. Oil and condensate sales during the current quarter were lower than the first quarter of 2018 primarily due to decreased production volumes (including the impact of certain adjustments related to our year-end receivable balances) and lower realized commodity prices. Our mineral and royalty interest oil and condensate volumes decreased 4% in the first quarter of 2019 relative to the corresponding period in 2018, primarily driven by production decreases in the Bakken/Three Forks play. Our mineral and royalty interest